PDC (Polycrystalline Diamond Compact) bits were introduced in the oil and gas industry in the mid 1970s. During the past 30 years, numerous technological improvements brought to the PDC cutters and bits have enabled them to take an important and growing share of the drilling bit market. In 2003, about 50% of the total footage drilled was with PDC bits compared to 26% in 2000. Further in 2003, the total revenue of PDC bits sales was around $600 million.
It has been difficult to extend the application of PDC bits in harder and more abrasive formations even with significant improvements. PDC bits have had improvements in bit hydraulics, tougher and more abrasion resistant PDC cutters and dynamic stability of PDC bits has resulted in continuously and significantly increasing the average rate of penetration (ROP) and bit life of PDC bits. Even such improvements have failed to extend the application of PDC bits in harder and more abrasive formations. Therefore historically, the use of PDC bits has been restricted to soft to medium and nonabrasive formations. A particular concern is the inability of a PDC bit to cut effectively, if at all, at the center of the drill bit.
Many improvements have been made in the quality and variety of the cutters and in new manufacturing techniques to prevent cutter wear and breakage. The improvements have, for example, focused on providing better impact and abrasion resistant diamond material and the interface geometry between the diamond layer and the tungsten carbide substrate. With the numerous innovations and technological breakthroughs, PDC bits drill faster, better and deeper, extending their application in harder and more abrasive formations, but a basic problem remains, the high inefficiency of the central cutters of the bit.
PDC bits, as opposed to roller cone bits, have no moving parts. The body of a PDC bit is typically manufactured from two different materials, steel bodied and matrix bodied bits. The steel bodied bit, machined and manufactured with steel stock, is better able to withstand impact load than matrix bodied bits. Steel bodied bits are generally preferred for soft and nonabrasive formations and large hole size. The main disadvantage of steel is that it is less erosion resistant than matrix and, consequently, more susceptible to wear by abrasive fluids. To reduce the bit body erosion, bits are “hardfaced” with a coating material that is more erosion resistant, and sometimes receives an anti-balling treatment for very sticky rock formations such as shales. Matrix bits are manufactured with tungsten carbide, which is more erosion resistant than steel. The matrix bits are preferred when using high solid-content drilling mud.
Typically, the PDC cutters are composed of a thin layer of polycrystalline diamond bonded to a cemented tungsten carbide substrate. The thin layer of polycrystalline diamond is up to approximately 3.5 mm thick. These PDC cutters are generally cylindrical with a diameter generally from about 8 mm up to about 24 mm. These PDC cutters may be available in other forms such as oval or triangle-shaped and are generally chamfered to increase the cutter's impact resistance.
Improvements have been made in the quality and variety of the cutters and in new manufacturing techniques to prevent cutter wear and breakage. In one aspect, these improvements concern a better impact and abrasion resistant diamond material. The interface geometry between the diamond layer and the tungsten carbide substrate are also improved. Due to the thermal limitations of the PDC bit wherein above 700° C. the diamond layer disintegrates as a consequence of cobalt expanding, much work has been done to produce a Thermally Stable Polycrystalline (TSP) cutter. It is desirable to have a TSP cutter that is stable up to 1,150° C. Thus, PDC bits have thermal limitations at temperatures above about 700° C. One of the reasons that a PDC cutter is so difficult to achieve is the lack of cutting efficiency at the center of the PDC bit.
Cutters are attached to the bit body using an alloy that must have the lowest possible melting point, good flow properties, excellent wettability and shear strength and bond well to tungsten carbide at low temperatures. The brazing is a critical operation in PDC bit manufacturing and silver is the predominant element. The highly controlled chemistry of the silver is necessary to provide the strength needed to braze the cutting elements to the matrix bit body. Thus, the matrix bit body is able to translate weight and rotation to the cutting structure. Due to the physical structure of a PDC bit, the cutters cannot be arranged to cover, and thus cut, the formation at the center of the bit.
PDC bits drill the rock formation by shearing, like the cutting action of a lathe, as opposed to roller cone bits that drill by indenting and crushing the rock. The PDC bit's cutting action plays a major role in the amount of energy needed to drill a rock formation, and can be modeled by studying the interaction between a single PDC cutter and the rock formation. Many models have been developed during the past 30 years to predict the forces on the PDC bit. The single cutter-rock models generally take into account the PDC cutter characteristics (cutter size, back rake angle, side rake, chamfer, etc.) and the rock mechanical properties to calculate the forces necessary to cut an amount of rock. The 2D or 3D rock-bit interaction model takes into account the bit characteristics (profile, cutter layout, gauges) and the bit motion to calculate the Weight On Bit (WOB), Torque On Bit (TOB) and side force on the bit at given operating conditions in a given rock formation, either isotropic or heterogeneous formations. Laboratory single-cutler tests and full scale PDC bit tests have been carried out at atmospheric pressure or under bore-hole conditions and tend to validate these models, enabling many advances made in bit design and optimization.
The design of a PDC bit is largely a compromise between many factors, such as, drillability, ROP, hydraulics, steerability and durability. Typically, the design emphasizes the three parts of the PDC bit that interacts with the rock formation: the cutting structure (bit profile and cutter layout characteristics), the active guage (guage cutters or trimmers), and the passive guage (guage pads). There are three basic types of PDC bit profile: flat or shallow cone, tapered or double cone and parabolic, according to IADC fixed cutter drill bit classification there are nine bit profile codes. The type of profile plays an important role for the bit stability and durability and bit directional responsiveness. The choice of bit profile depends on the type of application, and it is difficult to give or apply general rules. Nevertheless, it is generally thought that the bit cone tends to make the bit more stable and that very flat profiles are generally used for sidetrack applications.
The active gauge formed by the PDC's truncated-at-bit diameter constitutes the transition zone between the cutting zone and the positive gauge. These trimmers can be pre-flattened or rounded. The passive gauge or gauge pad plays an important role in the stability and in the directional responsiveness of the PDC bit. The passive gauge is reinforced by tungsten carbide inserts, diamonds or TSP to maintain the full gauge diameter of the drilled hole.
PDC bit drillabiity is certainly the most important factor affecting global drilling costs. The PDC cutter characteristics, back rake angle, cutter layout, cutter count and cutter size are the main parameters that control the drillability of the bit. The back rake angle is defined as the angle the cutter face makes with respect to the rock. The back rake angle controls how aggressively cutters engage the rock formation. Generally, as the back rake is decreased, the cutting efficiency increases, i.e., high ROP, however the cutter becomes more vulnerable to impact breakage. A large back rake angle will result in lower ROP but will typically result in a longer PDC bit life. Also, the side rake angle generally affects the cleaning of the cutters, as it helps to direct the cutting toward the periphery of the bit.
PDC cutter count and size are selected for a specific formation under specific operating conditions. The general rule is that small cutters and high cutter count are chosen for hard and abrasive rock formation, whereas large cutters and a reduced cutter count are preferred for soft to medium formation. Typically, the cutter count determines the number of blades required.
PDC bit stability is extremely important for the global drilling performance. A stable bit increases rate of penetration and bit life, improves hole quality and reduces the damage caused to downhole equipment. The three main vibration modes are axial resulting in bit bouncing, torsional resulting in stick-slip; and lateral resulting in whirl motions. Considerable research in PDC bit dynamics has led to balanced PDC bits minimizing the imbalance forces. In particular, the use of spiraled blades has increased PDC bit dynamics. Other techniques are anti-whirl bits, low-friction gauge pads, and full gauge contact design to make the bits more stable. A widely spread innovation consists in placing some impact arrestors or small round inserts behind the PDC cutters, which provide a better stabilization to axial and lateral modes of vibration.
The steerability of a bit corresponds to the ability of the bit to initiate a deviation. For example, high steerability for a bit implies a strong propensity for deviation, enabling a maximum dogleg potential. Generally speaking, and all things being equal, the short-gauge design is more steerable than long-gauge design, but may lead to poor borehole quality. To enhance toolface control during the sliding phase of a mud motor, some PDC bits have been designed to control lateral and axial aggressivity. This enables the directional drifter to control a PDC bit.
Advancements in PDC cutter technology have increased the development and performance of PDC bits. Cutters have mainly been evaluated in terms of their resistances to impact and abrasion because the primary reasons of bit failure are abrasive damage and impact loading damage. Additionally, other characteristics such as interface strength, thermal stability and fatigue are also analyzed. Maximizing these properties improves cutter durability that subsequently enhances PDC bit performance and drilling efficiency.
The size of nozzles made of tungsten carbide that are interchangeable depends on many factors, with the main factors being the size of the bit and the recommended hydraulic program. The bit hydraulic is fundamental for two main purposes. First, the drilling mud cleans the cuttings from the bit and prevents bit balling. Secondly, the mud cools the cutters to maintain the temperature below the critical 700° C. The conventional nozzles are circular and create a symmetric pressure distribution at the rock interface. Some improvements have been the development of nozzles with non-circular or fluted jets with specialized interior shapes. This enables a more efficient cleaning and cutter removal with increased turbulence under the bit resulting in a higher ROP. Computational fluid dynamics programs enable modeling of the fluid flow around bits inside a borehole to investigate quickly many bit designs and optimize fluid flow.
Typically, a PDC bit is designed for a specific application, depending mainly upon the rock formation to be drilled. It is therefore important to study the type of rock encountered during drilling using data and logs from offset wells. The mechanical and physical characteristics of the formation such as compressive strength, abrasiveness, elasticity, stickiness and pore pressure govern the choice of the PDC bit to be used. Design software can estimate rock strength from well logs and evaluate PDC bit performance to help in drilling bit selection. At the same time, drilling parameters or hydraulic aspects should also be studied to adjust the bit design.
PDC bits are also chosen for the type of application: directional drilling, slim hole, horizontal, motor drilling, turbo-drilling, reaming drilling, etc. Most bit manufacturers have their own line of PDC bits for rotary steerable systems (RSS), their own specialized PDC bits for drilling salt or shales, or for any particular application. The objective is always the same: to drill as fast as possible in a smooth way, and terminate the run with minimum wear to reduce overall drilling costs.
A feature of the present invention is to provide a PDC drill bit having a high efficiency for the central cutters of the bit.
Another feature of the present invention is to provide a PDC drill bit having an efficient angle with respect to attacking the portion of the formation central to the bit.
Another feature of the present invention is to provide a PDC drill bit that drills the formation at the center portion of the bit as well as at the extreme portions of the bit.
Another feature of the present invention is to provide a PDC drill bit that improves the drilling efficiency in the center of the bit.
Another feature of the present invention is to provide a PDC drill bit that increases the efficiency of the central cutters of a bit.
Another feature of the present invention is to replace the central cutters of a PDC bit with a more efficient cutting structure.
Yet another feature of the invention is to a PDC drill bit having a more efficient central cutting structure with a more normalized angle of attack.
Another feature of the present invention is to a PDC drill bit having a more efficient central cutting structure with an aggressive side rake angle.
Yet another feature of the present invention is to provide a method of drilling having more efficient central cutting structure.
Additional features and advantages of the invention will be set forth in part in the description which follows, and in part will become apparent from the description, or may be learned by practice of the invention. The features and advantages of the invention may be realized by means of the combinations and steps particularly pointed out in the appended claims.